Tamarack Valley Energy Ltd. Announces Record 2018 Financial and Operating Results Including 43% Increase in Total Adjusted Operating Field Netbacks, 20% Increase in Production and 22% Increase in Oil Reserves

TSX:TVE – CALGARY, Feb. 27, 2019 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2018 and the results of its independent oil and gas reserves evaluation as of December 31, 2018, prepared by GLJ Petroleum Consultants Ltd. (“GLJ”).  Selected financial, operational and reserves information is outlined below and should be read with Tamarack’s audited consolidated financial statements (“Financial Statements”), management’s discussion and analysis (“MD&A”) as of December 31, 2018, which are available on SEDAR at www.sedar.com and on Tamarack’s website at www.tamarackvalley.ca. The Company’s annual information form (“AIF”) for the year ended December 31, 2018 will be filed on SEDAR and available on Tamarack’s website by close of business February 27, 2019.

2018 Financial and Operating Highlights

• Maintained stable production volumes of 24,780 boe/d in Q4/18 relative to 24,765 boe/d in Q3/18, while investing only $25.8 million in capital expenditures, a $52.3 million reduction from the previous quarter.
• Total adjusted operating field netback (previously referred to as “adjusted funds flow”; see “Non-IFRS Measures”) increased 43% in 2018 to $226.5 million ($0.99 per share basic and $0.97 per share diluted), from $158.4 million in 2017 ($0.70 per share basic and diluted).
• In Q4/18, total adjusted operating field netback of $38.3 million exceeded capital spending of $21.0 million, net of acquisitions and dispositions, by $17.3 million, resulting in excess total adjusted operating field netback for the period, which was directed to debt repayment and continued funding of the Company’s active share repurchase program.
• Year over year, achieved a 20% increase in production, and an 8% increase in the oil and natural gas liquids (“NGL”) weighting percentage, while spending $9 million less capital, after acquisitions and dispositions, than the mid-point of the Company’s previous capital guidance.
• Full year 2018 net production and transportation expenses per boe were 6% lower relative to 2017, stemming primarily from increased production from the lower-cost Veteran area.
• Tamarack’s continued increase in oil and liquids weighting through 2018 largely contributed to 16% higher operating netbacks (see “Non-IFRS Measures”) compared to 2017, further supported by improved pricing and lower transportation expenses per boe year over year.
• Invested $219.2 million in total capital expenditures net of dispositions during 2018, which included drilling a total of 164 (158.2 net) wells, comprised of 129 (124.7 net) Viking oil wells, 19 (17.8 net) Cardium oil wells, 4 (4.0 net) Penny oil wells, 11 (10.7 net) Redwater oil wells, one exploratory vertical stratigraphic well and one (1.0 net) water source well.

2018 Reserve Highlights

• Tamarack’s strategy to enhance value through increased oil weighting was evidenced by increases to the Company’s crude oil reserves which grew by 22% for total proved plus probable (“TPP”), by 15% for total proved (“TP”) and 10% for proved developed producing (“PDP”), respectively, over 2017.
• Growth across all reserves categories on an absolute basis was achieved in 2018; increased TPP reserves by 11% to 101.6 million boe; increased TP reserves by 8% to 55.7 million boe; and increased PDP reserves by 2% to 31.8 million boe.
• On a per share basis (basic), realized growth of 12% in TPP, 9% in TP and 3% in PDP reserves, demonstrating Tamarack’s continued focus on enhancing per share metrics.
• Net asset value based on the net present values (discounted at 10%) of the TP and TPP reserves is $2.83and $5.95 per basic share, respectively. The net present value of reserves has been adjusted for net debt of $179.9 million but assumes no value for undeveloped land or infrastructure.
• Achieved attractive capital efficiencies through the 2018 development program, generating a TPP finding and development (“F&D”) and finding, development and acquisition (“FD&A”) cost recycle ratio of 2.4x and 2.5x, respectively, and a TP F&D and FD&A cost recycle ratio of 1.5x and 1.6x based on the 2018 average operating field netback of $30.05/boe.
• Crude oil weighting across reserves categories also increased to 58%, 55% and 52% for TPP, TP and PDP, respectively, compared to 54%, 52% and 49% for the same categories in 2017, driving oil and NGL weighting across all reserve categories to approximately 65% compared to 62% in 2017.
• The Company replaced 144% of production on a TP basis and 214% on a TPP basis.
• Achieved TPP F&D costs of $12.59/boe and TPP FD&A costs of $11.85/boe, both including the change in future development capital (“FDC”) contributing to reducing the realized three-year average TPP F&D costs to $15.10/boe and TPP FD&A costs to $16.75/boe, both including the change in FDC.
• Based on 2018 average production of 24,237 boe/d, achieved a TPP reserve life index of 11.5 years.

Financial & Operating Results

2018 In Review

Through 2018, Tamarack delivered another year of exceptional performance supplemented by an unwavering commitment to enhancing per share and debt-adjusted per share value.  In each quarter, the Company met or exceeded expectations for production while remaining focused on driving costs down and achieving strong capital efficiencies.  Tamarack grew annual production volumes 20% in 2018 over 2017, averaging 24,237 boe/d (65% oil and NGL), compared to 20,136 boe/d (60% oil and NGL) following a successful 2018 drilling program combined with strong capital efficiencies.  The Company’s 2018 average annual production was at the mid-point of its 2018 average guidance range of 24,000 to 24,500 boe/d (66% oil and NGL).  In Q4/18, Tamarack achieved record production of 24,780 boe/d (66% oil and NGL) exceeding the Company’s lower end of its exit 2018 guidance range of 24,500 to 25,000 boe/d.

Consistent with historical practices during periods of volatility in commodity prices, Tamarack remains disciplined in its capital allocation and preservation of balance sheet strength.  This became critical during the final quarter of 2018 when an unexpected and extreme widening of Canadian crude oil price differentials severely reduced the Company’s realized price for its oil and NGL products.  In response to this, Tamarack elected to defer $7.4 million of the $28.4 million in capital spending that had previously been planned for acceleration from 2019 into Q4/18.  As such, the Company’s Q4/18 capital spending totaled $21.0 million net of acquisitions and dispositions, bringing its total 2018 capital investment to $226.3 million ($219.2 millionincluding acquisitions, net of dispositions).  Tamarack remains focused on drilling wells which are expected to payout in 1.5 years or less and estimates it has more than nine years of development within its current inventory.

During Q4/18, capital was directed to drill a total of 24 (23.2 net) Viking oil wells and one (1.0 net) water source well in the Veteran area.  Of these Viking oil wells, 19 (18.5 net) are expected to be brought on production in Q1/19, while five (4.8 net) of the drilled Viking oil wells were also completed, equipped and tied-in during the period.  Six of the Viking wells are future Veteran waterflood injection wells, which will produce to recover the capital costs until the commencement of the injection project in the first half of 2019.  In addition, Tamarack completed and brought on production 18 (17.8 net) Viking oil wells and one (1.0 net) Penny oil well that had been drilled in late Q3/18.

Despite the weakness in realized oil prices during Q4/18, Tamarack generated total adjusted operating field netback of $38.3 million ($0.17 per share basic and diluted), exceeding its capital spending, including acquisitions and net of dispositions, by $17.3 million for the quarter.  The Company elected to direct excess total adjusted operating field netback to debt repayment and continued funding of Tamarack’s active normal course issuer bid (“NCIB”).  For the full year 2018, adjusted operating field netback totaled $226.5 million($0.99 per basic share; $0.97 per diluted share), an increase of 43% over $158.4 million ($0.70 per basic and diluted share) in 2017.  Based on the forward curve price deck, the Company anticipates generating excess total adjusted operating field netback in 2019 to again fully fund its capital program, achieve 3-5% debt-adjusted production per share growth in Q4/19 over Q4/18 and have incremental funds remaining.  With this situation and by maintaining financial flexibility, Tamarack retains optionality to increase drilling activity, pursue tuck-in acquisitions, repay debt or continue share buybacks under the NCIB depending on the prevailing price environment.  Year-end 2018 net debt totaled $179.9 million, which represents a net debt to Q4/18 annualized adjusted operating field netback ratio of 1.2 times, compared to 0.8 times at December 31, 2017.

Tamarack’s oil and NGL weighting continued to increase through 2018 and averaged 65%, compared to 60% in 2017, and largely contributed to operating field netbacks of $30.05/boe, 28% higher than in 2017.  Tamarack’s average per boe sales price increased 17% year-over-year to $45.08/boe in 2018 from $38.60/boe in 2017 while net production and transportation expenses per boe declined by 6%.  The Company anticipates its oil and NGL weighting will range between 64 to 66% of total 2019 production.

During 2018, Tamarack purchased and cancelled 3,025,000 outstanding common shares under the NCIB program, for a total investment of $11.7 million.  The NCIB provides management a tool that can be employed when there is a perceived misalignment between the Company’s prevailing share price and the underlying current and future potential value of its assets. In addition, it helps to offset the potential for dilutive impact that may be associated with the exercise and settlement of options issued under Tamarack’s stock-based compensation program.  In addition to the NCIB, the Company purchased 1,803,592 outstanding common shares in the open market for $5.8 million, which are held in trust and used to settle RSUs upon future exercise, further supporting Tamarack’s per share metrics.

2018 Year-End Reserves Summary

Tamarack continued to generate attractive capital efficiency metrics in 2018, despite a very challenging Q4/18 crude oil price environment which has had a severely negative impact on operating netbacks for the period.  The Company’s full year 2018 operating field netback was more representative of the performance through the year, averaging $30.05/boe, and reflecting the strategic capital shift to projects with higher oil and NGL weighting.  Using the Company’s full year operating field netback, Tamarack generated a TPP F&D recycle ratio of 2.4x, 1.5x for TP, and 1.2x for PDP, and FD&A recycle ratios of 2.5x for TPP, 1.6x for TP and 1.2x for PDP.  The Company maintained a consistent approach to reserves booking, with TP reserves including only 140.6 net Veteran and Consort horizontal Viking oil wells, 103.2 net Redwater and Saskatchewan horizontal Viking oil wells and 47.5 net undeveloped horizontal Cardium oil locations. Further, the FDC for 2019, within GLJ’s 2018 reserves evaluation, of $126.8 million is materially lower than Tamarack’s 2019 capital expenditure guidance of $170 to $180 million. The total FDC on a TP basis was $381.6 million and on a TPP basis was $700.2 million.

Consistent with Tamarack’s core strategy, the Company continued to take a long-term approach to the allocation of capital and development of its asset base in 2018, including the Veteran waterflood project.  During the year, the Company invested $30.3 million in waterflood capital, including constructing pipelines for the planned injectors, drilling a water source well, commencement of the water handling upgrades to the Veteran oil battery, drilling nine wells as future injectors in the Veteran unit and drilling six wells to be converted into injectors in East Veteran in 2019.  The results of this capital investment have been conservatively recognized, as GLJ assigned probable reserves of 4.9 million barrels of oil associated with the waterflood, with no reserves yet reflected in the PDP or TP categories.  Excluding waterflood capital from PDP and TP F&D costs (including FDC) results in $22.28/boe and $17.62/boe, respectively and generates recycle ratios of 1.3x and 1.7x for the same respective categories.  In 2019, Tamarack plans to invest an additional $20 million to further the waterflood project, which will benefit the Company in future years by improving oil recoveries, reducing corporate decline rates and increasing production rates over time, while utilizing existing Tamarack-owned infrastructure.

The following tables highlight Tamarack’s 2018 year-end independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2018 (the “GLJ Report”).  The GLJ Report has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook.  All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. The information included in the “Net Present Values of Future Net Revenue before Income Taxes” table below is based on an average of pricing assumptions prepared by three independent external reserves evaluators. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  Given Tamarack’s ongoing and extensive share buy-backs during 2018 under its NCIB and shares held in treasury to settle future restricted share unit (“RSU”) exercises, all per share reserves metrics below are based on basic shares outstanding.

Reserves Snapshot by Category:

Reserves Data (Forecast Prices and Costs) – Company Gross

Net Present Values of Future Net Revenue before Income Taxes Discounted at (% per year)

Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs

Future Development Capital Costs

The following is a summary of GLJ’s estimated future development capital required to bring proved and probable undeveloped reserves on production.

2019 Guidance

Our 2019 guidance remains unchanged with plans to invest between $170 and $180 million, funded entirely through adjusted operating field netback. This capital program is expected to result in production of 23,500 – 24,500 boe/d (64-66% oil and NGL). In the context of continued volatility in oil prices and supported by the Company’s exceptional operational execution, Tamarack remains committed to investing in longer-term projects, including the Veteran waterflood, which the Company expects will reduce the overall corporate decline rate in 2020 and enhance Tamarack’s sustainability.

Effective January 1, 2019 the Government of Alberta imposed production curtailments which, when combined with active production management and engagement from the producer community, have resulted in a significant narrowing of the differential into the early part of 2019.  The Company remains well positioned to withstand further crude oil price volatility given approximately 30% of its 2019 production is protected with hedges that include a US$60.00/bbl WTI put option and another approximately 3% is protected with fixed price contracts at US$64.60/bbl. Regardless, the Company will continue to closely monitor current and future commodity prices and price differentials. While the Company’s 2019 capital guidance assumes activity levels will be weighted evenly between H1 and H2 of 2019, the program timing for H1 has been designed to comply with the required production cuts.  Following expected stable production levels in H1/19 due to the mandatory volume curtailments, Tamarack anticipates realizing a meaningful ramp-up in production volumes during the second half of 2019, assuming no additional government intervention.

The Company’s 2019 guidance and assumptions are outlined below:

• Annual average production between 23,500 – 24,500 boe/d (64-66% oil and NGL), with 2019 exit production estimated between 25,500 – 26,500 boe/d (64-66% oil and NGL);
• Capital expenditures between $170 to $180 million to maintain the Alberta government’s mandatory production curtailments during Q1 of 2019;
• Estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio of approximately 1.0 times with an estimated $100 million of liquidity on existing credit facilities; and
• Average 2019 commodity price assumptions of WTI US$50.00/bbl, Edmonton Par C$52.33/bbl, WTI / Edmonton Par differential of US$10.75/bbl, AECO $1.31/GJ and a Canadian/US dollar exchange rate of $0.75.

About Tamarack Valley Energy Ltd.

Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack’s strategic direction is focused on two key principles: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; and (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Cardium and Viking fairways in Alberta that are economic over a range of oil and natural gas prices. With this type of portfolio and an experienced and committed management team, Tamarack intends to continue delivering on its strategy to maximize shareholder returns while managing its balance sheet.